Devon Energy Corp. plans to cast off the asset that brought it to the unconventional dance floor in the early 2000s, the Barnett Shale, along with the Canadian portfolio, to complete its transformation into a pure-play U.S. oil producer.

The Oklahoma City-based independent also cut its capital expenditures (capex) from 2018 by 14% to $2.05-2.31 billion, with spending in the STACK, i.e. the Sooner Trend of the Anadarko Basin, mostly in Canadian and Kingfisher counties, reduced by one-third to $200 million. Permian Basin Delaware capex was trimmed 10% to $100 million. Capex was raised slightly for 2019 in the Eagle Ford Shale and in the Powder River Basin (PRB), where oil output is forecast to jump 50% by year’s end.

Devon is targeting $780 million in cost reductions by 2021, with a target of 70% of the cuts by the end of this year.

“With our world-class U.S. oil resource plays rapidly building momentum and achieving operating scale, the final step in our multi-year transformation is an aggressive, transformational move that will accelerate value creation for our shareholders by further simplifying our resource-rich asset portfolio,” said CEO Dave Hager.

“New Devon will emerge with a highly focused U.S. oil portfolio and has the ability to substantially increase returns and profitability as we aggressively align our cost structure to expand margins with this top-tier oil business. The new Devon will be able to grow oil volumes at a mid-teens rate while generating free cash flow at pricing above $46/bbl.”

At $46/bbl West Texas Intermediate, Devon expects to achieve breakeven free cash flow (FCF). At $50, the producer estimated it could generate $800 million in cumulative FCF in 2019-2021.

While the Barnett made Devon an onshore natural gas powerhouse, attention today is on oil prospects, particularly in Texas and across the Midcontinent.

Devon transformed itself in late 2002 after gaining entry into the Barnett with the acquisition of Mitchell Energy & Development Corp. for $3.1 billion in cash and stock, which at the time made it the second largest independent U.S. natural gas producer after Anadarko Petroleum Corp. Devon gained the expertise of the crew working for founder George Mitchell, considered the godfather of unconventional drilling. Mitchell Energy toiled for years in the Barnett to extract gas, eventually cracking the code to combine hydraulic fracturing techniques with horizontal drilling. The rest, as they say, is history.

Devon perfected those unconventional techniques, leading the way for other operators to tap into shale and tight resources that have since transformed the world’s energy markets. With stagnant gas prices and more enticing oil prospects to tap, the Barnett has become a minor player for Devon and other operators. It’s time to put those legacy assets aside, Hager said.

“2018 was a pivotal year for Devon as we took several significant steps toward achieving our long-term strategic goals,” he said. “Operationally, we successfully transitioned our franchise U.S. oil business into full-field development, which resulted in high-return, light-oil production advancing 20% in the fourth quarter. In addition to this strong operating performance, we made substantial progress high-grading our asset portfolio, building per-share value through our industry-leading share repurchase program and reducing our outstanding debt by more than 40%.”

Devon’s U.S. oil business is attaining the highest margins and returns in the portfolio. During the final three months of 2019, light oil production from retained U.S. assets averaged 126,000 b/d, a 20% increase year/year, driven by growth in the Permian Delaware, Eagle Ford, PRB and STACK.

The strongest asset-level performance was achieved by the Delaware in southeastern New Mexico, where oil production increased 49% from 4Q2017 driving volumes to 84,000 boe/d. Since the start of 2019, volumes have accelerated, with January rates averaging 96,000 boe/d, a 14% sequential increase.

Canadian oil production averaged 120,000 b/d net in the fourth quarter. Output was reduced by about 17,000 b/d because of management’s decision to curtail volumes in response to market conditions. The curtailments were offset partially by royalty adjustments related to the lower commodity price environment. The Alberta government late last year announced a cut of 325,000 b/d off the province’s oil production that began Jan. 1 to try boosting severely depressed prices blamed on a glut backing up behind stalled pipeline projects.

Overall, Devon’s net production averaged 532,000 boe/d in 4Q2018, exceeding midpoint guidance by 3,000 boe/d, with oil output representing the largest component at 47% of total volumes.

Estimated proved reserves were 1.9 billion boe at the end of 2018, with proved developed reserves accounting for 77%. Reserve additions primarily were from the U.S. assets, where proved oil reserves increased 16% year/year. Devon last year added 232 million boe of reserves (extensions and discoveries), representing a reserve replacement rate of about 150%. Excluding property acquisition costs, reserves were added at a finding cost of less than $10/boe.

Net earnings were $1.1 billion ($2.48/share) in 4Q2018, versus $304 million (8 cents) in the year-ago quarter. Operating cash flow was $542 million, down from $553 million.

For 2018, net earnings were $3.2 billion ($1.53/share) versus 2017 profits of $1.08 billion ($1.71). Operating cash flow was $2.2 billion, nearly flat year/year. The company generated additional cash from its ongoing divestitures, with total proceeds reaching nearly $5 billion at the end of the 2018.

In the fourth quarter, upstream revenue, excluding commodity derivatives, totaled $1.1 billion, an 18% year/year decline. Devon blamed the miss on historically wide differentials in Canada, which negatively impacted the realized price on heavy oil production. The weak pricing was mitigated through a Western Canadian Select basis swap hedge position that generated $144 million of cash settlements.

For 2018, upstream revenue, excluding commodity derivatives, totaled $5.7 billion, a 10% increase from 2017. Firm transport and marketing agreements, which provide most of the U.S. oil production direct access to Gulf Coast pricing, contributed to the gains. Combined with price protection provided by regional basis swaps, U.S. oil realizations averaged nearly 100% of the West Texas Intermediate benchmark.